Demand for oil and gas reserves has increased over the past several decades due to steady population growth and the industrialization of new markets. At the same time, conventional fields are maturing and experiencing a decrease in oil and gas production as reservoir pressures drop and/or water production increases. These economic factors, which effect the oil and gas industry, have led to recent developments and advances in exploration, drilling, and production technologies as companies try to either increase production from mature fields or bring new opportunities on-line. One technology area that has seen increased interest from oil and gas producers and vendors alike is subsea processing.
Subsea processing is not a new concept in the oil and gas industry; however, recent economic factors have led to far more applications ranging from simple single-phase or multiphase boosting and subsea separation and boosting to future gas compression projects. Vendors are trying to establish technologies that can meet the unique challenges of subsea processing, and producers are trying to stay ahead of the competition by developing, qualifying, and applying these new technologies.
Subsea processing may include subsea separation, which can be segregated into two-phase, gas-liquid separation and three-phase, gas-oil-water separation. Overall, subsea two-phase separation presents the following benefits: reduced back-pressure acting on the well leading to higher production rates (accelerated revenue) and recoverable reserves (total revenue): the ability to overcome long step-out distances between field and host facility (fewer boosting stations required to reach host facility); reduced topsides infrastructure; the ability to absorb transient flow conditions such that gas-liquid slugs do not affect performance of downstream equipment (e.g., pumps and/or wet-gas compressor): lower energy requirements than multiphase boosting of full well-stream (higher efficiency of rotating equipment); and mitigation of certain flow assurance issues through bulk separation of gas and produced water phases (assuming two lines are installed back to host facility). Subsea three-phase, gas-oil-water separation may yield the following benefits related to the bulk removal of the produced water phase: the ability to debottleneck existing topsides water handling/treatment facilities; the ability to inject produced water into dedicated disposal well or back into the reservoir for pressure maintenance (lower energy requirements than platform- and/or land-based water injection); the ability to use smaller production lines back to host facility due to removal of non-revenue stream (e.g., produced water): and mitigation of certain flow assurance issues through bulk separation of oil and produced water streams. These benefits may make it desirable to develop a multiphase separation system to establish a technological advantage and earn partner or choice status for future subsea separation applications. An advancement of this nature may enable production of Arctic, deepwater, or other remote oil and gas fields for which production is not currently possible. Subsea separation may act as an enabler in these cases by, for example, removing bulk water from the production streams and mitigating flow assurance concerns for longer distance tieback applications.
One challenge with subsea three-phase separation is the formation of stable oil/water emulsion layers. Testing has shown that stable oil/water emulsion layers can significantly affect the quality of the oil and water outlets from the subsea separator. If separation of heavy oil (known to form stable emulsions) is desired, then oil/water separation may require longer residence times and lower fluid velocities. However, this approach may not be economic for offshore and subsea applications due to size, weight, and fabrication constraints. Designing a deepwater, oil-water separator with oil residence times of greater than about 3-5 minutes can be challenging. Analogous onshore separators may require about 10-15 minutes residence time. Therefore, decreasing the throughput of the subsea separation system may be required for heavy oil applications, which may bottleneck the oil/water separation process. Similarly, opportunities also exist on onshore and topsides separators that suffer from the formation of stable oil/water emulsions. In conventional applications, production chemicals such as demulsifiers and/or heat may be applied to alter the interfacial tension and destabilize the oil/water emulsion. In subsea applications, heat may not be a cost effective option or, in some cases, may even be technically infeasible. Consequently, dosing with production chemicals is customarily preferred. However, dosing can have a significant effect on the capital and operating costs associated with a subsea installation.
The cost of developing and applying a subsea separation system may be significant and may become uneconomical if the system cannot provide sufficient production increases to offset the cost. Consequently, the design of subsea processing systems may include a balance between what is practically achievable under the vessel size constraints due to pressure and what production rate is required to make the project economical. Any technological advance aimed at enhancing the overall performance of the oil-water separation, which is often the bottleneck of such a system, could become the deciding economic factor of a future project. For this reason, extraction and processing of the stable oil/water emulsion layer from a subsea separator may prove beneficial.
Injectability of the produced water stream may also affect the successful operation, and therefore economics, of subsea separation installations that employ oil-water separation. Therefore, the removal of oil contamination, which can have a significant effect on injectability of the water stream, may be important. It may be advisable to provide monitoring and/or frequent sampling of the produced water quality in order to avoid future issues with the injection reservoir. These aspects may be particularly important when injecting back into the production reservoir for pressure maintenance as plugging and/or permeability issues in the perforated zone could lead to an inability to inject the produced water and/or result in other production issues.